Predictive models for sandstone diagenesis

Surdam, Ronald C.; MacGowan, Donald B.; Dunn, Thomas L.

doi:10.1016/0146-6380(91)90081-t

Cited by 12 publications

(7 citation statements)

References 19 publications

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“…The use of numerical simulation can overcome this issue. For most sandstone reservoirs, diagenetic modelling can be a useful tool for predicting reservoir quality (Surdam et al ., ; Berger et al ., ; Le Gallo et al ., ; Jones & Xiao, ; Ajdukiewicz & Lander, ; Tobin et al ., ; Bjørlykke & Jahren, ). Numerical simulation of diagenesis can effectively simplify the heterogeneities of the geological bodies and the complexity of the comprehensive process, so as to provide a quantitative evaluation of reservoir quality for petroleum exploration.…”

Section: Discussionmentioning

confidence: 98%

“…Quartz precipitated because of the presence of a large amount of Si in the fluid. In the third stage, along with the organic acid incursion, some minerals (for example, calcite, chlorite and feldspar minerals) dissolved more drastically; this greatly affected the reservoir porosity and the formation of secondary pores (Surdam et al ., ; Wei et al ., ; Liermann et al ., ). Quartz precipitated variably under an acidic fluid condition.…”

Section: Discussionmentioning

confidence: 99%

“…Acetic acid is quite commonly found in oil field production water. To mimic this, dilute acetic acid was chosen as the third fluid type in this study (Surdam et al ., ; Harrison & Thyne, ; Liang et al ., ; Wei et al ., ).…”

Section: Introductionmentioning

confidence: 99%

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Fluid–rock interactions during continuous diagenesis of sandstone reservoirs and their effects on reservoir porosity

Yang

Liu

et al. 2017

Sedimentology

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The Cretaceous sandstone reservoir in the Kuche Depression, Tarim Basin, western China, was investigated with reference to its reservoir property evolution during diagenesis. Six general diagenetic stages were recognized through petrographic, mineralogical and geochemical analyses. Fluid–rock interaction experiments were conducted under these six continuous diagenetic conditions, that is with a simulation sequence of compaction → early diagenesis → organic acid incursion I → elevated temperature/pressure → organic acid incursion II → late diagenesis. Corresponding to these six experimental stages, a total of six models were constructed. Finally, an extended model of fluid–rock interaction during diagenesis at a geological timescale (from 30 Ma to present) was constructed after various parameters had been validated. Results demonstrate that the diagenetic stages from both the experimental and numerical simulations generally matched findings obtained from the petrographic and geochemical analyses: (i) With compaction becoming weakened, cementation by various minerals was gradually increased. (ii) Quartz overgrowth occurred because the contemporaneous sedimentary water was alkaline. (iii) Most minerals (for example, calcite and feldspar minerals) displayed dissolution owing to the first organic acid incursion, resulting in the visual porosity increasing to 29·26%. (iv) Increases in temperature and pressure caused a minor fluctuation of the porosity change. (v) The cement that formed during earlier stages largely dissolved with the second organic acid incursion. (vi) During the last stage, the reservoir fluid was diluted by sedimentary alkaline water and most minerals precipitated under an alkalic environment. The present porosity simulated is about 11·4%, comparable with the actually measured data. This study demonstrates that the combination of petrographic observations, laboratory experiments and numerical simulations can not only reconstruct the diagenetic process, but also provide a quantitative evaluation and prediction of reservoir petrophysical properties.

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Section: Discussionmentioning

confidence: 98%

Section: Discussionmentioning

confidence: 99%

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Fluid–rock interactions during continuous diagenesis of sandstone reservoirs and their effects on reservoir porosity

Yang

Liu

et al. 2017

Sedimentology

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“…Research on oil-field brines and pore-water evolution during burial of sedimentary successions (e.g., Hayes 1991;Surdam et al 1989;Surdam et al 1991) suggests that during burial diagenesis, decarboxylation of kerogen produces carboxylic and phenolic acids in the temperature range from 80u to 120u C (MacGowan and Surdam 1990). This process leads to secondary porosity due to the destruction of carbonates (e.g., Hayes 1991;Surdam et al 1991). From the perspective of the low-pH conditions that favor marcasite precipitation (Murowchick and Barnes 1987), a burialdiagenesis scenario can certainly lead to marcasite formation in sediments.…”

Section: Discussionmentioning

confidence: 99%

Marcasite in Black Shales--a Mineral Proxy for Oxygenated Bottom Waters and Intermittent Oxidation of Carbonaceous Muds

Schieber¹

2011

Journal of Sedimentary Research

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Black shales in the geologic record have long been considered to reflect deposition under anoxic or even euxinic conditions. Although bottom-water anoxia favors deposition of black shales, certain biological indicators, such as benthic fossils and bioturbation, suggest that bottom-water conditions may not have been as persistently anoxic as commonly presumed. Examination of twelve marine carbonaceous shale-bearing units, ranging in age from Middle Proterozoic to Cretaceous, suggests that in addition to paleontological clues, early diagenetic marcasite formed in uncompacted surficial sediments is a reliable indicator of oxygen-bearing bottom waters. Marcasite requires low pH values to form, and oxidation of already existing sedimentary pyrite provides a plausible chemical scenario to achieve that condition. In the studied examples, degraded pyrite framboids and corrosion features on pyrite grains indicate partial pyrite destruction in surface sediments, and suggest that intermittent reoxidation of earlier formed iron sulfides may indeed have generated the low pH values required for marcasite formation. Thus, observations of textures spatially associated with secondary marcasite growth are consistent with a scenario whereby oxygen in overlying sea water drove downward migration of oxidation fronts. Pervasive marcasite in black shales from a wide range of occurrences suggests multiple reoxygenation events during the deposition of these shale units and calls for more dynamic ocean circulation than previously assumed. The latter consideration may, for example, prove important for those instances where a black shale is associated with an oceanic anoxic event (OAE), because these are commonly presumed to have been deposited under fully anoxic conditions.

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“…Thus, dissolution may have approximately coincided or overlapped with hydrocarbon formation and may represent pH lowering as organic acids were generated during burial diagenesis of organic matter. Research on oil field brines and pore water evolution during burial suggests that the initial stages of smectite transformation are followed by (and overlap with) decarboxylation of kerogen and a buildup of carboxylic and phenolic acids in the temperature range from 80 to 120°C (MacGowan and Surdam, 1990;Hayes, 1991;Surdam et al, 1991). In sandstones this stage is associated with formation of secondary porosity and destruction of carbonates (Hayes, 1991).…”

Section: Pore Typesmentioning

confidence: 99%

An SEM Study of Porosity in the Eagle Ford Shale of Texas—Pore Types and Porosity Distribution in a Depositional and Sequence-stratigraphic Context

Schieber¹,

Lazar²,

Bohacs³

et al.

The Eagle Ford Shale

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Although typically considered with a focus on high-resolution petrography, shale porosity should not be thought of as a stand-alone petrographic feature. Shale and mudstone porosity is the outcome of a long succession of processes and events that span the continuum from deposition through burial, compaction, and late diagenesis. For the Eagle Ford Shale this journey began with accumulation in intra-shelf basins at relatively low latitudes on a southeast-facing margin during early parts of the late Cretaceous. To understand the factors that generated and preserved porosity in this economically important interval, a scanning electron microscope study on ion-milled drill-core samples from southern Texas was conducted to understand the development of petrographic features and porosity and place them in stratigraphic context. The studied samples show multiple pore types, including pores defined by mineral frameworks (clay and calcite), shelter pores in foraminifer tests and other hollow fossil debris, and pores in organic material (OM). In many instances, framework and shelter pores are filled with OM that has developed pores due to maturation. Large bubble pores in OM suggest that hydrocarbon liquids were left behind in or migrated into these rocks following petroleum generation and that the bubbles developed as these rocks experienced additional thermal stress. These larger OM pores indicate deeper seated interconnection on ion-milled surfaces and in three-dimensional image stacks.

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Predictive models for sandstone diagenesis

Cited by 12 publications

References 19 publications

Fluid–rock interactions during continuous diagenesis of sandstone reservoirs and their effects on reservoir porosity

Fluid–rock interactions during continuous diagenesis of sandstone reservoirs and their effects on reservoir porosity

Marcasite in Black Shales--a Mineral Proxy for Oxygenated Bottom Waters and Intermittent Oxidation of Carbonaceous Muds

An SEM Study of Porosity in the Eagle Ford Shale of Texas—Pore Types and Porosity Distribution in a Depositional and Sequence-stratigraphic Context

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